In the oil and gas industry, gaining an understanding of the wettability characteristics or wetting condition of a hydrocarbon-bearing, subsurface formation (a “reservoir”) may be particularly advantageous. For instance, this understanding may help in the optimisation of field development, since wettability may have an effect on reserve calculation and/or the dynamic behaviour of a reservoir.
Wettability may be defined as the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids.
Thus, for example, wettability may describe the relative preference of a rock to be covered by a certain phase, e.g. water or oil. For example, a rock may be said to be water-wet if the rock has a much greater affinity for water than for oil. Thus, in the case of a water-wet porous rock containing water and oil phases within its pores, substantially all of the internal surface of the pores would be covered with a layer of water. In this case, the water may be termed the “wetting phase”.
Conversely, in the case of an oil-wet porous rock, substantially all of the internal surface of the pores would be covered with a layer of oil. In this case, the oil may be termed the “wetting phase”.
Similarly, a porous rock of mixed wettability may contain some pores which are water-wet and some which are oil-wet. Also, some regions of an individual pore may be water-wet, while others are oil-wet.
In practice, it will be appreciated that extreme water-wetness or oil-wetness is rare in oil-bearing reservoirs.
It should be appreciated, however, that for a two-phase fluid within a porous rock, the wetting phase will cover more pore surface area and have a stronger surface affinity with the pore walls than the non-wetting phase.
In fluid systems comprising a gaseous phase, e.g. gas-liquid systems, it may be safely assumed that gas is not the wetting phase.
The wettability of a porous rock will depend on the type of rock and will also be affected by any minerals present within the pores. For instance, clean sandstone or quartz may be extremely water-wet, while most rock formations of oil-bearing reservoirs typically may be of mixed-wettability. For a reservoir, wettability alteration from the original water wetting state to a mixed wetting state may have occurred after crude oil migrated into a reservoir trap and reduced the water saturation of the reservoir down to the connate water saturation over geological time. The reservoir wettability depends on crude oil composition, connate water chemistry, and mineralogy of the rock surface, as well as temperature, and pressure and saturation history of the reservoir. The initial fluid saturation distribution in an oil-bearing formation is dependent on the equilibrium between capillary forces and gravity forces at the reservoir scale and at the pore scale. The wetting state can vary with pore and pore-throat geometry. During the oil migration process, gravity is insufficient to overcome the large capillary pressure within micropores, and thus typically micropores remain fully connate water saturated, therefore retaining their original water-wet state. While large pores are often invaded by oil, a connate water film on the rock surfaces of the large pores usually remains. The wettability alteration within the large pores depends on the stability of this water film. In extreme conditions, the water film may be stable and fully coats the surface area of the large pores thereby keeping the oil phase from having direct contact with the pore surface. Thus over geological time, the large pores remain water-wet. Alternatively, the entire surface of the large pores may become coated by the oil phase such that the large pores are oil-wet. Typically, the large pore surfaces are partially in contact with both the water phase and the oil phase, and therefore have mixed-wetting characteristics.
Traditionally, wettability has been characterised in the laboratory using either the Amott or US Bureau of Mines (USBM) indices. However, the methods by which these indices are usually determined are intrusive and are very time consuming. Moreover, they cannot be readily transferred to the field.
It is known that nuclear magnetic resonance (NMR) techniques may be used to ascertain information regarding fluids contained within a porous medium. Advantageously, using NMR techniques offers a non-intrusive means for determining in-situ wettability of fluids in reservoir rocks, i.e., the NMR measurement process does not interfere with the fluid distribution within the pores of the rock. Hence, NMR techniques may be applied to monitor ongoing dynamic processes comprising wettability alteration, such as, ageing and secondary or tertiary oil recovery processes.
Proton (1H) NMR techniques may be particularly well suited for studies of fluids containing water and hydrocarbon phases, e.g. water and oil, within a porous medium.
NMR spectroscopy may be used to measure the spin-lattice (longitudinal) relaxation time (T1) and/or the spin-spin (transverse) relaxation time (T2) of the fluid. For instance, proton (1H) NMR spectroscopy measures the relaxation time for protons within the fluid. From these measurements it may be possible to elucidate certain information concerning the fluid and/or the porous medium.
For instance, core samples may be taken for subsequent analysis using land-based NMR equipment.
Alternatively, NMR logging tools may advantageously be deployed downhole. Such tools typically employ so-called low field spectroscopy.
However, NMR logging tools also suffer from certain drawbacks. For instance, they cannot be used in wellbores or sections thereof which are lined with metal casing. Also, current tools typically can only obtain information in the near-wellbore region, e.g. typically within a radial distance of about 4 inches (10 cm) from the wellbore. It is envisaged, however, that future generations of NMR logging tools may be able to obtain information relating to regions further from the wellbore.
Oil may be produced from a reservoir in a variety of stages, which may be classified as primary, secondary and tertiary stages.
In a primary oil recovery stage, the natural energy of the reservoir is sufficient to produce oil without any assistance. However only around 10 to 15 percent of the original oil in place of a reservoir is recovered during primary recovery.
In some reservoirs, however, the natural reservoir pressure may not be sufficient to drive oil unaided up a production well to the surface. Therefore, it may be necessary to artificially boost oil production. In this regard, it is known that oil production from a reservoir may be assisted by injection of immiscible fluids, such as water or gas, into the reservoir so as to maintain reservoir pressure, and/or to displace oil towards a production well. Injection of such immiscible fluids generally produces about 20 to 40 percent of the original oil in place.
Where the fluid is unmodified, typically seawater or other readily available water, this process may be classified as being a secondary oil recovery process (alternatively a secondary mode process). In general, such a secondary oil recovery process may be referred to as a water flood or water flooding.
Where the fluid has been treated in some way to modify its properties, this process may be classified as being a tertiary oil recovery process. For instance, tertiary recovery processes may include low salinity water flooding in which a source water such as seawater is treated to reduce its salinity prior to injection into the reservoir and processes in which the to-be-injected fluid comprises one or more specially chosen additives, e.g. chemicals and/or microbes. By appropriately modifying the injection fluid, tertiary oil recovery processes may be used to boost oil production from and/or extend the production life of a reservoir. Typically, tertiary oil recovery processes may displace oil from a reservoir which is not displaced by secondary oil recovery processes. Tertiary recovery processes may often be referred to as enhanced oil recovery (EOR) processes. The EOR techniques offer prospects for ultimate recovery of 30 to 60 percent, or more, of original oil in place.
During the production life of a reservoir different methods of oil recovery may be employed. For instance, initially the reservoir may be produced by a primary recovery method. However, after a while, the reservoir pressure may fall and it may become necessary to utilise secondary oil recovery processes. A period of secondary oil recovery may be followed by one of the EOR processes, in order to maximise production from the reservoir. Of course, the person skilled in the art will appreciate that other sequences are possible: for instance, it may be the case that the reservoir is never produced in primary recovery because the natural reservoir pressure is not high enough; alternatively or additionally, a period of EOR may be applied just after primary recovery, with this EOR process being referred to as a secondary mode EOR process. In contrast, an EOR process may be carried out after the completion of a secondary oil recovery process, with this EOR process being referred to as a tertiary mode EOR process.